This disclosure relates generally to the field of drilling wellbores through subsurface rock formations. More particularly, the disclosure relates to method for removing fluid that has entered the wellbore from subsurface formations outside the wellbore.
Drilling wellbores through subsurface rock formations includes inserting a drill string into the wellbore. The drill string, which is typically assembled by segments (“joints” or “stands”) of pipe threadedly coupled end to end) has a bit at its lower end. The drill string is suspended in a hoist unit that forms part of a drilling “rig.” During drilling, a specialized fluid (“mud”) is pumped from a tank into a passage in the interior of the drill string and is discharged through courses or nozzles on the bit. The mud cools and lubricates the bit and lifts drill cuttings to the surface for treatment and disposal. The mud also typically includes high density particles such as barite (barium sulfate), hematite (iron oxide), or other weighting agents suspended therein to cause the mud to have a selected density. The density is selected to provide sufficient hydrostatic pressure in the wellbore to prevent fluid in the pore spaces of the rock formations from entering the wellbore. The density is also selected to maintain mechanical integrity of the wellbore.
Wellbores drilled through subsurface formations below the bottom of a body of water, particularly if the water is very deep (e.g., on the order of 1,000-3,000 meters or more) may require special equipment for effective drilling. An example drilling system for such water depths is shown in FIG. 1. The drill string 28 extends from a drilling rig (not shown for clarity) and is disposed in a wellbore 14 being drilled through rock formations 12 below the bottom of a body of water 10 such as a lake or the ocean. A wellhead 16 including a plurality of sealing devices collectively called a “BOP stack” is disposed at the top end of a surface casing 14A cemented in place to a relatively shallow depth below the mud line. A marine riser 26 extends from the upper part of the wellhead 20 to the drilling rig (not shown). The riser 26 usually has auxiliary lines associated with it known as “choke” lines 24, and a “kill line” 22. Fluid may be pumped into such lines from the rig (not shown) toward the wellbore 14 or may be allowed to move from the wellbore 14 toward the surface. Valves 18, 20 control fluid movement at the lower end of the kill line 22. Corresponding valves 30, 32 control fluid movement at the lower end of the choke line 24.
In the present example, the riser 26 is hydraulically opened to the wellbore 14 below. In order to maintain a hydrostatic pressure in the wellbore annulus 13 that is lower than would be provided if the entire length of the riser 26 were filled with mud, the riser 26 may be partially or totally filled with sea water. See, for example, U.S. Pat. No. 6,454,022 issued to Sangesland et al. As the mud leaves the wellbore annulus 13 (the space between the drill string and the wellbore wall), it is diverted, through suitable valves 34, 36 to a pump 38 that lifts the mud to the surface through a separate mud return line 40. Typically, the pump 38 is operated so that the interface between the drilling mud and the water column above in the riser 26 is maintained at a selected level. Maintaining the selected level causes a selected hydrostatic pressure to be maintained in the wellbore 14.
The issue dealt with by methods according to the present invention is to safely remove from the wellbore 14 any fluid which enters from the rock formations 12. Such fluid, by reason of its entry, is at a higher pressure than the total hydrostatic pressure exerted by the mud column in the annulus 13 and the column of sea water in the riser 26. Methods known in the art for dealing with such fluid entry require “shutting in the well”, meaning that the BOP stack is closed to seal against the drill string 28, and fluid pumping is stopped. Frequently during such operation, the density of the drilling fluid will be increased by adding more dense, powdered material to the mud. See for example U.S. Pat. No. 6,474,422 issued to Schubert et al. for an example of a kick control method.
It is also possible that the pressures necessary to be applied to the mud return pump and its connecting lines may be exceeded if conventional kick control methods are used.
It is desirable to have a method for removing kick fluid from a wellbore that does not require the kick fluid to go through the pump, but maintains well bore pressures at acceptable levels. These pressures must be high enough to keep additional formation fluids from entering the wellbore from one formation, while not exceeding the fracture pressure (pressure that cases wellbore fluids to enter the formation) of other exposed formations, most specifically the formation at the last casing shoe, which is the end of the last installed casing.